Exploring for potential hydrocarbon reservoirs, determining the economic feasibility of producing the hydrocarbons, and developing the production plan, including where to drill wells, often uses seismic data to identify the structural features of the subsurface and well log data to identify the stratigraphy of the subsurface. The stratigraphy allows determination of the depositional setting, which is used for reservoir delineation and economic evaluation including risk analysis. The stratigraphy can be determined at the well locations but can only be estimated away from the wells.
Seismic exploration involves surveying subterranean geological media for hydrocarbon deposits. A survey typically involves deploying seismic sources and seismic sensors at predetermined locations. The sources generate seismic waves, which propagate into the geological medium creating pressure changes and vibrations. Variations in physical properties of the geological medium give rise to changes in certain properties of the seismic waves, such as their direction of propagation and other properties.
Portions of the seismic waves reach the seismic sensors. Some seismic sensors are sensitive to pressure changes (e.g., hydrophones), others to particle motion (e.g., geophones), and industrial surveys may deploy one type of sensor or both. In response to the detected seismic waves, the sensors generate corresponding electrical signals, known as traces, and record them in storage media as seismic data. Seismic data will include a plurality of “shots” (individual instances of the seismic source being activated), each of which are associated with a plurality of traces recorded at the plurality of sensors.
Seismic data is processed to create seismic images that can be interpreted to identify subsurface geologic features including hydrocarbon deposits. The seismic data may also be used to generate a velocity model of the subsurface using semblance analysis, tomography, and/or full waveform inversion. The velocity model based on the seismic data may be used in a seismic imaging method such as Gaussian beam migration, reverse time migration (RTM), or other imaging methods, to generate a 2-D or 3-D seismic image volume suitable for interpretation. The seismic velocity is influenced by many factors including compaction, pore pressure, lithology and so on, therefore seismic velocity itself is in general deemed unsuitable for interpretation. The velocity model without any modification is not appropriate for direct use in stratigraphic interpretation of the subsurface or for risk element evaluation because it is difficult to differentiate between different facies, particularly different shale facies.
Conventional regional stratigraphic interpretation methods mainly involve seismic facies analysis by mapping seismic stacks and calibrating it with wells. This can provide estimates of stratigraphic interpretations between wells; however, in areas where seismic data and/or wells are limited or seismic data quality is poor, seismic facies analysis can be very subjective.
There exists a need for methods to further process a velocity model to be used in combination with a seismic image volume to improve interpretation of subsurface structural and stratigraphic features for better evaluation of potential hydrocarbon reservoirs in the subsurface.